1. Field of the Invention
The present invention relates generally to processes for controlling the emission of nitrogen containing oxides from, and the growth of organisms, such as bacteria and algae, in, open cooling towers and the like in which ammonia and nitrite-containing waters are cooled.
2. Background Discussion
Subterranean reservoirs of aqueous geothermal fluids--steam, hot water, and hot brine--exist in many regions of the world. Such geothermal fluid reservoirs, many of which contain vast amounts of thermal energy, are most common where the near-surface temperature gradient of the earth is abnormally high, as is evidenced by unusually great volcanic, fumarole, and/or geyser activity. As an example, significant geothermal fluid sources are found along the Pacific Ocean Rim--a region long known for its high level of volcanic activity.
Aqueous geothermal fluids have, in some inhabited regions, been used for centuries for the therapeutic treatment of physical disorders. In these and/or in some other inhabited regions, such as Iceland and the Paris Basin of France, geothermal fluids have also long been used as heat sources for industrial processes and for heating dwellings and other buildings. Moreover, in some places, such as Italy and Northern California, geothermal steam has been successfully used for a number of years to generate commercially significant amounts of electric power. In the late 1970s, for example, about 2 percent of all the electric power used in the State of California was produced by geothermal steam at The Geysers in Northern California, and presently enough electric power is generated at The Geysers to satisfy the combined electricity needs of the cities of San Francisco and Oakland, Calif. More recently, moderate amounts of electric power have been generated, notably in the Imperial Valley of Southern California near the Salton Sea, by geothermal brine, which is much more difficult to use than geothermal steam.
Such factors as the steep increases, in the early 1970s, in the cost of petroleum products and natural gas and projected future shortages and high costs of such resources have led to the recently increased interest in further developing the use of geothermal fluids as alternative, and generally self-renewing, electric power plant "fuels." Much of this effort has been and is being directed toward developing more economically practical systems and processes for using geothermal brine to generate electric power because, although more difficult than geothermal steam to use, there are many more good sources of geothermal brine than there are good sources of geothermal steam.
General processes by which geothermal brine can be used to generate electric power have, of course, been known for some time. Geothermal brine, having a wellhead temperature of over about 400.degree. F. and a wellhead pressure of over about 400 psig, can, for example, be flashed to a reduced pressure to convert some of the water or brine into steam. Steam produced in this manner is then used in generally conventional steam turbine-type power generators to generate electricity. On the other hand, cooler, less pressurized, geothermal brine can be used in closed-loop, binary fluid systems in which a low-boiling point, secondary liquid is vaporized by the hot brine. The vapor produced from the secondary liquid is then used in a gas turbine-type power generator to generate electricity, the vapor being recondensed and reused. In both such cases, the "used" geothermal brine is most commonly reinjected into the ground to replenish the aquifer from which the liquid was produced and to prevent ground subsidence. Reinjection of geothermal brine is also often important to avoid problems typically associated with the disposal of the large amounts of saline and usually highly-contaminated liquid involved.
In spite of such general processes for using geothermal brine for producing electric power being known, difficult and costly problems are commonly encountered with the actual use of the heavily contaminated, saline, and corrosive brines. Moreover, these problems are frequently so costly to solve that the production of reasonable amounts of electric power at competitive rates by the use of geothermal brines has often been extremely difficult to achieve in many locations.
As mentioned above, many of these serious problems associated with the production and use of geothermal brines for the generating of electric power can be attributed to the usually complex chemical composition and extremely corrosive nature of many geothermal brines. At aquifer temperatures and pressures--which are often well in excess of 400.degree. F. and 400 psig--aqueous geothermal liquids leach large amounts of salts, minerals, and elements from the aquifer formations, the geothermal liquids (brines) presumably being in chemical equilibrium with their producing formations.
Thus, although their compositions may vary considerably from location to location, geothermal brines typically contain very high levels of dissolved salts and silica, and appreciable amounts of dissolved metals and such non-condensable gases as hydrogen sulfide, ammonia, and carbon dioxide. Geothermal brines are usually acidic, with typical wellhead pH's of between about 5 and about 5.5. As a combined result of their composition and high temperature, geothermal brines are not only frequently some of the most corrosive liquids known, but most tend, without appropriate treatment, to rapidly deposit a tough, tenacious, siliceous scale onto contacted surfaces of pipe, valves, vessels, and so forth, especially in regions of the brine handling system downstream of flashing vessels in which brine pressure is greatly reduced.
Adding greatly to the problems associated with producing and using geothermal brines for the generation of electric power is the need for very large, continuous flows of brine in order to generate even relatively moderate amounts of electric power. As an illustration, the production of only about 10 megawatts of electric power requires a continuous flow of over a million pounds per hour of high temperature and pressure geothermal brine. Consequently, even relatively low-capacity geothermal brine power plants ordinarily require several very costly brine production and reinjection wells, and large quantities of expensive, large size, corrosion-resistant pipe, fittings, pumps, valves, flashing and clarifying vessels, filters and so forth just for extracting, handling, and disposing of the huge flows of geothermal brine needed. In addition, an associated power generating facility is ordinarily required for each brine handling facility.
One of the many problems which has added to the overall cost of producing electric power by the use of geothermal brines, relates to the undesirable emission of nitrogen dioxide (NO.sub.2) from cooling tower waters used to extract waste heat from treated brine prior to its injection back into the earth. This is formed by the oxidation of ammonia in the brine by naturally occurring bacteria therein with the nitrites being formed therein by the reaction thereof in the cooling tower effluent with ferrous iron present in the brine. Nitrites can also produce acids which are quite corrosive to the cooling system and disposal piping.
Other difficult problems which, as is apparent from the discussion below, are related to the nitrogen dioxide emissions problem are the corrosion, by the steam condensate (which is used for cooling tower makeup), of metal parts of the condensate handling system and the rapid growth of organisms (including bacteria, fungi, and algae) in such parts of the condensate handling systems as open cooling towers and associated condensate catch basins. Unless controlled, these corrosion problems require the use of costly, corrosion-resistant materials or the frequent costly replacement of common steel components. In turn, the growth of organisms in the condensate cooling towers and catch basins usually not only adds substantially to condensate-handling system corrosion problems but also causes the fouling and loss of efficiency of cooling towers and other parts of the condensate handling system, the latter requiring frequent, costly system cleaning. It is, of course, to be appreciated that whenever system shutdown is required to replace corroded pipe or equipment or to clean the system of organism-caused contaminants, the resulting loss of electric power revenue during shutdown usually adds substantially to the overall cost associated with the servicing operations.
To overcome these and other corrosion problems in condensate-handling systems, corrosion inhibitors are commonly added to the condensate of steam derived from ammonia-containing brines. The use of heavy metal corrosion inhibitors has been effective in controlling the growth of organisms in open condensate cooling towers and catch basins since they are toxic to the organisms.
Such multi-function, heavy metal corrosion inhibitors would, therefore, seem to be ideal for use in systems which handle corrosive condensate of steam derived from ammonia-containing geothermal and other brines. However, a serious disadvantage is that the heavy metal sludges formed by the use of heavy metal corrosion inhibitors is now classified as a toxic or hazardous waste material in many localities. Consequently, the disposal of these sludges, which may, for example, be formed in a geothermal brine power plant, is difficult and expensive--and is destined to become even more difficult and expensive in the future, as more stringent controls are applied to the disposal of such materials and as hazardous waste disposal sites become scarcer, more remote, and more costly to use.
Thus, in spite of their effectiveness in inhibiting corrosion and also for controlling the growth of organisms, the continued use of heavy metal corrosion inhibitors in systems handling ammonia-containing condensate is becoming increasingly less practical.
Non-heavy metal corrosion inhibitors, which do not form hazardous waste materials in the presence of ammonia, carbon dioxide and/or hydrogen sulfide, have thus recently been used in some condensate handling systems of the type mentioned above. Representative of these non-heavy metal corrosion inhibitors are such inorganic, phosphate-based materials as Betz Dianodic II, available from Betz Laboratories, Inc., Trevose, Pa.
However, unlike their counterpart heavy metal corrosion inhibitors, phosphate-type corrosion inhibitors have not been effective in controlling either hydrogen sulfide and nitrogen dioxide emissions or the growth of organisms. The use of such alternative types of corrosion inhibitors has, as a result, created an important need for a compatible process (or processes) for controlling hydrogen sulfide and/or nitrogen dioxide emissions and organism growth in systems for handling steam and condensate derived from hydrogen sulfide, carbon dioxide and ammonia-containing geothermal brines.
It is, however, important that any new process for controlling nitrogen dioxide emissions from, and the growth of organisms in, steam condensate handling portions of geothermal brine power plants not only be effective, for example, to avoid penalties for excessive NO.sub.2 emissions, but that it also be economical to use. If a process is effective for controlling NO.sub.2 emissions and organism growth but is uneconomical--for example, if it is more costly than the cost of disposing of the heavy metal sludges produced by the use of heavy metal corrosion inhibitors--the process is of little, if any, practical use in actual geothermal brine power plants.